Artificial lift methods are commonly used to increase the flow rates of liquids in production wells that have insufficient pressure to bring the production fluids to the surface. This is often the case, for example, for crude oil or a mature well wherein the well pressure has decreased. The artificial lift methods used include injecting gas or water further down the well, or introducing a mechanical device inside the well to artificially increase the well pressure, for example, an Electrical Submersible Pump (ESP).
Where a mechanical device such as an ESP is deployed inside a well, it is necessary to monitor the condition and performance of the device. In the case of an ESP, it is important to monitor the fluid level in the well to ensure that the ESP is surrounded by liquid to prevent it from overheating or running dry, which can lead to extensive pump damage and considerable repair costs for the pump operators. Such monitoring is often done using acoustic pulse fluid level measurement techniques, wherein an acoustic pulse or wave is transmitted into a well via an acoustic wave generation tool.
Known systems for acoustic pulse fluid level monitoring include the ‘Model M’, manufactured by Echometer Co., of Texas, USA, which utilises acoustics to determine the distance from the surface to the liquid level in the casing annulus of a well. A pressure pulse is generated from a gas-gun or microphone attachment that is connected to the surface casing annulus valve. The pressure pulse travels down the casing annulus gas and is reflected by collars, the liquid level and other obstructions. A microphone in the wellhead attachment converts the pressure pulses into electrical signals that are amplified, filtered and recorded on a strip of paper. The record shows the number of tubing collars from the surface to the liquid level and hence the liquid level depth can be determined.
Acoustic reflections can also be generated and monitored using a surface noise source such as a pressure pulse gun and surface microphone. For example, the Acoustic Fluid Logger IV System manufactured by Sage Technologies, Inc, of Texas, USA, includes a pressure pulse gun charged with compressed gas. When the gun is fired, reflections from the liquid are registered by a microphone inside the gas gun and transmitted to a fluid logger. This data is then transferred to a computer for analysis.
Methods of fluid level detection such as those described above require extensive equipment to firstly generate the acoustic waves, secondly to detect the acoustic reflections from the fluid and then to analyse the measured data. This can be costly, time intensive and disruptive to the operation of the oil well. In addition, such techniques only provide measurements at discrete points in time, and are not conducive to continuous or almost-continuous monitoring. A more convenient and economical way of detecting the fluid level in a well using an acoustic noise source is therefore required, and preferably one which can be used substantially continuously.
Fiber optic based distributed acoustic sensors are known in the art. Such systems employ fiber optic cables to provide distributed acoustic sensing whereby the optical fiber cable acts as a string of discrete acoustic sensors, and an optoelectronic system measures and processes a backscattered signal from a light pulse sent along the fiber. The operation of such a system is described next.
A pulse of light is sent into the optical fiber, and as the pulse travels along the fiber a small amount of light is naturally back scattered from along the length of the fiber by Rayleigh, Brilliouin and Raman scattering mechanisms. The back scattered light is carried back towards the source where the returning signal is measured against time, allowing measurements in the amplitude, frequency and phase of the back scattered light to be determined. If an acoustic wave is incident upon the cable, the glass structure of the optical fiber is caused to contract and expand within the incident vibro-acoustic field of the acoustic wave, consequently varying the optical path lengths between the back scattered light scattered from different locations along the fibre. This variation in path length is measured as a relative phase change, allowing optical phase angle data to be used in combination with backscatter return timing information to provide information relating to the incident acoustic waves along the length of the fiber.
Optical fibre based distributed acoustic sensors (DAS) that operate in accordance with the above described principles are known in the art. One high performance example is the iDAS™, available from Silixa Limited, of Elstree, UK. Further details of the operation of a suitable DAS are given in WO2010/0136809 and WO2010/136810, which also disclose that distributed acoustic sensors may be used for in-well applications, in that the acoustic noise profile can be used to measure the flow by noise logging at every location along the well. In addition, the noise spectrum can be used to identify the phase of the fluid.